The Athabasca bitumen resource in Alberta, Canada is one of the world's largest deposits of hydrocarbons. The leading EOR process for in situ recovery of bitumen is SAGD. But the reservoir quality is often impaired by top gas (gas over bitumen), top water (water over bitumen), water lean zones, bottom water (water under bitumen), shale and/or mudstone deposits (barrier or baffle), thin pays, and bitumen quality gradients, (i.e. reservoir inhomogeneities).
The Athabasca bitumen resource in Alberta, Canada is unique for the following reasons:                (1) The resource, in Alberta, contains about 2.75 trillion bbls. of bitumen (Butler, R. M., “Thermal Recovery of Oil & Bitumen”, Prentice Hall, 1991), including carbonate deposits. This is one of the world's largest liquid hydrocarbon resources. The recoverable resource, excluding carbonate deposits, is currently estimated as 170 billion bbls. split at 20% mining (43 billion bbls.) and 80% in situ EOR (136 billion bbls.) (CAPP, “The Facts on Oil Sands”, November, 2010). The in situ EOR estimate is based on SAGD, or a similar process.        (2) Conventional oil reservoirs have a top seal (cap rock) that prevents oil from leaking and traps (contains) the resource. Bitumen is formed by bacterial degradation of a lighter source oil to a stage where the degraded bitumen is immobile, under reservoir conditions. Bitumen reservoirs may be usually self-sealed (no cap rock seal). If an in situ EOR process hits the top of the bitumen zone (ceiling), the process may not be contained, and the bitumen may easily be contaminated by water or gas from above the bitumen.        (3) Bitumen density is close to the density of water or brine. Some bitumens are more dense than water; some are less dense than water. During the bacterial-degradation and thus formation of bitumen, the hydrocarbon density may pass through a density transition and water may, at first, be less dense but become more dense than bitumen. Bitumen reservoir water zones are found above the bitumen (top water), below the bitumen (bottom water), or interspersed in the bitumen net pay zone (water lean zones (WLZ)).        (4) Most bitumen was formed in a fluvial or estuary environment. With a focus on reservoir impairments, this has 2 consequences. First, there will be numerous reservoir inhomogeneities. Second, the scale of the inhomogeneities is likely to be less than the scale of the SAGD recovery pattern (see FIG. 1) or less than about 1000 m in size. The expectation is that a SAGD EOR process will encounter several inhomogeneities within each recovery pattern.        
Today's leading in situ EOR process to recover bitumen from Canada's oil sands is SAGD (Steam Assisted Gravity Drainage). The current estimate of recoverable bitumen using in situ EOR is 136 billion bbls (CAPP (2010)). This is one of the world's largest, recoverable liquid hydrogen resources in the world.
SAGD is a delicate process. Temperatures and pressures are limited by saturated steam properties. Gravity drainage is driven by a pressure differential as low as 25 psia. Low temperatures (in a saturated steam process) and low pressure gradients make the SAGD process susceptible to impairments from reservoir inhomogeneities, as above.
SAGDOX is a more robust process. Because of the combustion component, at equal pressures, temperatures may be higher than saturated-steam temperatures. SAGDOX geometry (i.e. well locations) may compensate for some of the reservoir impairments that affect SAGD.
This invention describes how SAGDOX wells may be drilled and completed to ameliorate damages due to reservoir inhomogeneities as discussed above.